Current energy sources may have limitations in supply or possible environmental effects that have led to research efforts to identify alternate energy sources. For example, the combustion of hydrocarbons generates carbon dioxide. Other energy sources, such as wind and solar energy, are intermittent.
Another source of energy that can be considered is geothermal. Currently, a number of installations around the world use the energy from natural hot water or steam produced from subsurface formations to run turbines or heat facilities. However, energy from these natural hydrothermal formations can be limited by the geographic and geologic availability of such formations. In contrast, so-called “hot dry rock” formations underlie many regions of the world and contain substantial heat energy. These formations can be problematic to access due to their depth, which may be about two to ten kilometers, or more, below the surface of the Earth.
Heat may be extracted from a hot dry rock formation by injecting a fluid (typically water or brine) into the rock formation using injection wells, flowing the fluid through a network of fractures within the rock formation to absorb heat from the rock, and producing a heated fluid through production wells. Such a process is referred to as “hot dry rock” (HDR) geothermal energy extraction. The geothermally heated fluid that is produced may be used to directly heat industrial processes or may be used in conjunction with a thermodynamic cycle to generate power or electricity. In certain applications, a fracture network within the formation is stimulated to improve fluid transmissibility through the fractures. Stimulation may involve hydraulic fracturing, injection of proppants, pressurization to cause fracture slippage, or chemical treatments to cause solids dissolution and widen fractures. Systems which are stimulated are referred to as “enhanced geothermal systems” or “engineered geothermal systems” (EGS).
Conventional hot dry rock geothermal production often utilizes continuous injection of water into wells with production at distant wells (for example, at a well spacing of 500-1000 m). Ideally, the fracture system within the subterranean rock will permit injected water to distribute fairly uniformly throughout the rock to extract geothermal heat. Many subterranean rocks formations (for example, granite basement rock) have extensive networks of natural fractures, although in certain cases the fractures need to be dilated or opened to allow commercially valuable flow rates and heat extraction performance.
The presence of an extensive fracture network is useful for effective performance of HDR geothermal energy extraction. Thermal diffusion is a slow process and, thus, rock that is more than several meters away from fluid flow through a fracture will not have its heat extracted in a commercially acceptable timeframe. Moreover, any real network of fractures will be composed of fractures of differing widths which will affect the fluid flow. More specifically, fluid flow is prone to channel preferentially through a small subset of the fractures within a rock section, such as the larger fractures. When this occurs, only a small fraction of the heat in the target section is actually removed in a reasonable amount of time. Additionally, the fluids produced from the formation may quickly cool to non-economic levels as the rock adjacent to the primary flow fractures are drained of their heat. Hence, using conventional HDR geothermal energy extraction methods, only a small fraction of hot subterranean rock is likely to have suitable fracture networks to permit economic energy extraction.
U.S. Pat. No. 4,220,205 describes a method of producing self-propping fluid-conductive fractures in rock. The method comprises pressurizing a subsurface formation and causing opposing faces of fractures to shear displace. After the shear displacement, the fractures are held open by the misfit between the opposing faces. The tendency for fracture faces to shear displace arises from shear stress retained from the original formation of the fractures.
Early descriptions of hot dry rock geothermal energy extraction were described in U.S. Pat. Nos. 3,786,858 and 3,817,038. U.S. Pat. No. 3,786,858 describes extracting energy from a dry igneous rock geothermal reservoir by a method that includes drilling a well in hot igneous rock to reach at least 150° C., hydraulically fracturing the rock, and circulating water through the crack system. U.S. Pat. No. 3,817,038 describes a method of heating an aqueous fluid in a dry geothermal reservoir formation penetrated by an injection well and a production well, forcing the fluid into the formation with simultaneous heating, and recovering the heated fluid via the production well.
One way to improve heat extraction from the whole of a targeted rock volume is to utilize cyclic injection and production using separate injection and productions wells into the rock volume. For example, cyclic operation of hot dry rock reservoirs where fluid is alternately injected and then produced, may improve access to portions of a rock section. See Duchane, D. V., “Commercialization of Hot Dry Rock Geothermal Energy Technology”, Geothermal Resources Council Transactions, 15, Oct. 1991, 325-331.
Other injection schemes may use a single injection well to feed two production wells to produce fluid at moderate rather than low pressures so as to dilate fractures during production. The production may be performed cyclically, for example 12-hours on/12-hours off, while injection remains constant. In this way pressure can be built up in the reservoir and fluids better contact the whole of the rock volume. See Robinson, A., “Alternate Operating Strategies for Hot Dry Rock Geothermal Reservoirs”, Geothermal Resources Council Transactions, 15, Oct. 1991, 339-345.
U.S. Pat. No. 4,074,754 describes a method for producing geothermal energy from a subterranean high temperature reservoir by injecting low salinity water at ambient surface temperature, allowing the injected water to become heated in the reservoir, and then producing water through a well to be used as a source of energy. The method describes a staged well development plan for geothermal extraction. The staged plan utilizes cyclic injection and production through the same well for geothermal energy extraction. In one embodiment the method involves first, second, and third rows of wells drilled into the reservoir; and conducting injection-production cycles in each well of said first row of wells; shutting in each of the first row of wells; conducting injection-production cycles in each well of the second row of wells; conducting injection-production cycles in each well of the third row of wells; and then conducting injection in each well of the second row of wells while producing from each well of said first row of wells and third row of wells. The patent indicates that injection of cold water reduces the temperature of the reservoir around the injection wells and the invention permits reheating of that reservoir volume by overinjecting in selected wells to displace reservoir heat back to the vicinity of cold wells.
Patent application US2007/0223999 (hereinafter “the '999 application”) describes a method of connecting a vertical well to two or more vertically-stacked fractured sections into which water is injected and from which water is produced. The reservoir is cyclically produced by flooding a fractured section with water to a point of dilation of the fractures. However, if the fractured segments were in close proximity, fluid communication between sections would be a problem. However, the '999 application does not address how to minimize separations between target sections to prevent fluid communication between horizontally or vertically neighboring sections. Such fluid communication could degrade performance by permitting pressure leak off from one section to another. In the '999 application, fluid communication between the sections is prevented by placing large vertical separations between the completion points, for example, 5000 ft or more. Separate injection and production wells may be used, but the method described in the '999 application does not permit substantially uniform injection and production into individual wells connected to vertically-stacked sections. This may lead to operational and reliability issues by repeatedly cycling pressure within the wells and surface equipment.
Although prior methods describe cyclic injection-production schemes, issues concerning the uniformity of total production and the minimization of spacing between neighboring sections (to lower detrimental flow between sections) have not been adequately addressed. Thus, improved methods are desirable for producing geothermal energy from neighboring sections.